Edgar Filing: MURPHY OIL CORP /DE

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2007

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

71-0361522

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)

200 Peach Street

P.O. Box 7000, El Dorado, Arkansas

71731-7000

(Address of principal executive offices)

(Zip Code)

(870) 862-6411

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and larger accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2007 was 188,503,412.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


		Page
Part I – Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets		2

Consolidated Statements of Income		3

Consolidated Statements of Comprehensive Income		4

Consolidated Statements of Cash Flows		5

Consolidated Statements of Stockholders’ Equity		6

Notes to Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition		17

Item 3. Quantitative and Qualitative Disclosures About Market Risk		26

Item 4. Controls and Procedures		26

Part II – Other Information

Item 1. Legal Proceedings		27

Item 1A. Risk Factors		28

Item 4. Submission of Matters to a Vote of Security Holders		28

Item 6. Exhibits and Reports on Form 8-K		29

Signature		30

PART I – FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) June 30, 2007			December 31, 2006*

ASSETS
Current assets
Cash and cash equivalents	$	693,456		543,390
Accounts receivable, less allowance for doubtful accounts of $7,856 in 2007 and of $10,408 in 2006		1,034,084		995,089
Inventories, at lower of cost or market
Crude oil and blend stocks		192,790		73,696
Finished products		227,990		224,469
Materials and supplies		124,906		112,912
Prepaid expenses		93,892		136,674
Deferred income taxes		24,728		20,861

Total current assets		2,391,846		2,107,091

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,224,001 in 2007 and $2,872,293 in 2006		5,815,633		5,106,282
Goodwill		48,213		44,057
Deferred charges and other assets		332,974		225,731

Total assets	$	8,588,666		7,483,161

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	4,887		4,466
Notes payable		13,608		2,659
Accounts payable and accrued liabilities		1,299,933		1,240,977
Income taxes payable		124,063		63,003

Total current liabilities		1,442,491		1,311,105

Notes payable		1,102,225		833,126
Nonrecourse debt of a subsidiary		2,943		7,149
Deferred income taxes		709,432		621,329
Asset retirement obligations		274,476		237,875
Deferred credits and other liabilities		450,326		327,964
Minority interest		25,564		23,340

Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		—		—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 188,767,558 shares in 2007 and 187,691,508 shares in 2006		188,768		187,692
Capital in excess of par value		501,320		454,860
Retained earnings		3,649,278		3,349,832
Accumulated other comprehensive income		248,729		131,999
Treasury stock, 264,146 shares of Common Stock in 2007 and 119,308 shares in 2006, at cost		(6,886	)	(3,110	)

Total stockholders’ equity		4,581,209		4,121,273

Total liabilities and stockholders’ equity	$	8,588,666		7,483,161

*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; See Note B.

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars except per share amounts)


	Three Months Ended June 30,					Six Months Ended June 30,
	2007			2006*		2007		2006*
REVENUES
Sales and other operating revenues	$	4,614,598		3,798,032		8,042,184		6,785,151
Gain (loss) on sale of assets		455		(109	)	808		(1,373	)
Interest and other income		(1,426	)	995		5,519		6,403

Total revenues		4,613,627		3,798,918		8,048,511		6,790,181

COSTS AND EXPENSES
Crude oil and product purchases		3,654,703		2,996,955		6,379,087		5,304,451
Operating expenses		309,952		279,542		606,435		508,409
Exploration expenses, including undeveloped lease amortization		30,168		30,273		78,504		93,436
Selling and general expenses		54,729		46,548		107,718		86,923
Depreciation, depletion and amortization		114,740		102,206		222,727		199,564
Impairment of long-lived assets		40,708		—		40,708		—
Accretion of asset retirement obligations		3,802		2,576		7,264		5,076
Net costs associated with hurricanes		—		43,051		—		78,773
Interest expense		17,121		11,678		32,610		22,241
Interest capitalized		(16,588	)	(9,039	)	(31,245	)	(18,628	)
Minority interest		(2	)	—		24		—

Total costs and expenses		4,209,333		3,503,790		7,443,832		6,280,245

Income before income taxes		404,294		295,128		604,679		509,936
Income tax expense		154,052		78,954		243,803		177,779

NET INCOME	$	250,242		216,174		360,876		332,157

INCOME PER COMMON SHARE
NET INCOME – BASIC	$	1.33		1.16		1.93		1.79
NET INCOME – DILUTED	$	1.32		1.14		1.90		1.76

Average common shares outstanding – basic		187,615,633		185,919,897		187,361,136		185,813,948
Average common shares outstanding – diluted		190,160,989		189,101,235		189,954,414		189,047,627

*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; See Note B.

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)


	Three Months Ended June 30,			Six Months Ended June 30,
	2007		2006*	2007	2006*
Net income	$	250,242	216,174	360,876	332,157

Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains (losses)		—	2,941	—	(8,837	)
Reclassification to income		—	405	—	8,952

Total cash flow hedges		—	3,346	—	115
Net gain from foreign currency translation		100,277	72,828	109,757	71,510
Retirement and postretirement benefit plan adjustments, net of taxes		5,628	—	5,628	13

COMPREHENSIVE INCOME	$	356,147	292,348	476,261	403,795

*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; See Note B.

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Six Months Ended June 30,
	2007			2006*
OPERATING ACTIVITIES
Net income	$	360,876		332,157
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		222,727		199,564
Impairment of long-lived assets		40,708		—
Amortization of deferred major repair costs		10,062		8,632
Expenditures for asset retirements		(3,872	)	(2,525	)
Dry hole costs		28,420		41,200
Amortization of undeveloped leases		12,846		11,030
Accretion of asset retirement obligations		7,264		5,076
Deferred and noncurrent income tax charge (benefit)		18,971		(19,621	)
Pretax (gain) loss from disposition of assets		(808	)	1,373
Net increase in noncash operating working capital		(31,522	)	(393,669	)
Other operating activities, net		17,639		8,932

Net cash provided by operating activities		683,311		192,149

INVESTING ACTIVITIES
Property additions and dry hole costs		(813,426	)	(610,479	)
Proceeds from sales of assets		17,944		12,195
Expenditures for major repairs		(8,214	)	(8,099	)
Other – net		(6,924	)	(6,137	)

Net cash required by investing activities		(810,620	)	(612,520	)

FINANCING ACTIVITIES
Increase in notes payable		279,950		269,989
Decrease in nonrecourse debt of a subsidiary		(4,884	)	(4,667	)
Proceeds from exercise of stock options and employee stock purchase plans		20,791		11,109
Excess tax benefits related to exercise of stock options		10,706		5,217
Cash dividends paid		(56,420	)	(41,996	)
Other		(759	)	—

Net cash provided by financing activities		249,384		239,652

Effect of exchange rate changes on cash and cash equivalents		27,991		10,098

Net increase (decrease) in cash and cash equivalents		150,066		(170,621	)
Cash and cash equivalents at January 1		543,390		585,333

Cash and cash equivalents at June 30	$	693,456		414,712

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	143,319		263,550

Interest paid more than (less than) amounts capitalized		(66	)	2,615

*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; See Note B.

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)


	Six Months Ended June 30,
	2007			2006
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—		—

Common Stock – par $1.00, authorized 450,000,000 shares, issued 188,767,558 shares at June 30, 2007 and 186,926,283 shares at June 30, 2006
Balance at beginning of period	$	187,692		186,829
Exercise of stock options		1,043		97
Issuance of time-based restricted stock		33		—

Balance at end of period		188,768		186,926

Capital in Excess of Par Value
Balance at beginning of period		454,860		437,963
Exercise of stock options, including income tax benefits		30,717		3,717
Restricted stock transactions and other		3,794		(7,433	)
Amortization, forfeitures and other		11,365		11,186
Sale of stock under employee stock purchase plans		584		306
Reclassification from Unamortized Restricted Stock Awards upon adoption of SFAS No. 123R		—		(16,410	)

Balance at end of period		501,320		429,329

Retained Earnings
Balance at beginning of period as previously reported		—		2,744,274
Cumulative effect of adopting FASB Staff Position No. AUG AIR-1		—		59,051

Balance at beginning of period as adjusted		3,349,832		2,803,325
Cumulative effect of changes in accounting principles		(5,010	)	—
Net income for the period		360,876		332,157
Cash dividends		(56,420	)	(41,996	)

Balance at end of period		3,649,278		3,093,486

Accumulated Other Comprehensive Income
Balance at beginning of period as previously reported		—		131,324
Cumulative effect of adopting FASB Staff Position No. AUG AIR-1		—		2,029

Balance at beginning of period as adjusted		131,999		133,353
Cumulative effect of change in accounting principle		1,345		—
Foreign currency translation gain, net of taxes		109,757		71,510
Cash flow hedging losses, net of taxes		—		115
Retirement and postretirement benefit plan adjustments, net of taxes		5,628		13

Balance at end of period		248,729		204,991

Unamortized Restricted Stock Awards
Balance at beginning of period		—		(16,410	)
Reclassification to Capital in Excess of Par Value upon adoption of SFAS No. 123R		—		16,410

Balance at end of period		—		—

Treasury Stock
Balance at beginning of period		(3,110	)	(22,990	)
Exercise of stock options		—		13,345
Sale of stock under employee stock purchase plans		620		390
Awarded restricted stock, net of forfeitures		—		7,023
Cancellation of performance-based restricted stock and forfeitures		(4,396	)	—

Balance at end of period		(6,886	)	(2,232	)

Total Stockholders’ Equity	$	4,581,209		3,912,500

See notes to consolidated financial statements, page 7.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.

Note A – Interim Financial Statements

The consolidated financial statements of the Company presented herein have not been audited by independent auditors, except for the Consolidated Balance Sheet at December 31, 2006. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, 2007, and the results of operations and cash flows for the three-month and six-month periods ended June 30, 2007 and 2006, in conformity with accounting principles generally accepted in the United States. In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the United States, management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2006 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the six months ended June 30, 2007 are not necessarily indicative of future results.

Note B – New Accounting Principles Adopted

Turnaround Accounting

Effective January 1, 2007, the Financial Accounting Standards Board’s (FASB) Staff Position No. AUG AIR-1 (FSP AUG AIR-1), Accounting for Planned Major Maintenance Activities, became effective for the Company. FSP AUG AIR-1 no longer permits the Company to use the accrue-in-advance method of accounting for planned major maintenance activities such as refinery turnarounds. The Company has chosen to use the permitted deferral method for such planned major maintenance activity. All prior period financial statements have been adjusted to reflect the adoption of FSP AUG AIR-1 as if the deferral method was in effect in prior periods. A cumulative after-tax adjustment of $61.1 million has been recorded as of January 1, 2006 as an increase to Stockholders’ Equity to effect the adoption of FSP AUG AIR-1. Net income for the three-month and six-month periods ended June 30, 2006 has been restated to reflect the earnings for the periods as if FSP AUG AIR-1 had been in effect during the periods. The effect for the three-month and six-month periods ended June 30, 2006 was an increase to net income of $2.1 million ($0.01 per diluted share) and $4.2 million ($0.03 per diluted share), respectively, while the effect for the three-month and six-month periods ended June 30, 2007 was an increase to net income of $0.7 million (less than $0.01 per diluted share) and $2.4 million ($0.01 per diluted share), respectively. As presented on the consolidated balance sheet as of December 31, 2006, the previously reported liability for Accrued Major Repair Costs of $71.2 million has been removed and a noncurrent asset of $37.4 million, representing the unamortized deferred costs of planned major maintenance activities as of that date, has been added to Deferred Charges and Other Assets. In association with the adoption of FSP AUG AIR-1, the Company will present expenditures for major repairs as an investing activity in the Consolidated Statement of Cash Flows. The following consolidated financial statement items as of December 31, 2006 and for the three-month and six-month periods ended June 30, 2006 were affected by this change in accounting principle.


	December 31, 2006
(Thousands of dollars)	As Previously Reported		FSP AUG AIR-1 Adjustment		As Adjusted
Consolidated Balance Sheet
Deferred charges and other assets	$	188,297	37,434		225,731
Deferred income tax liabilities		581,920	39,409		621,329
Accrued major repair costs		71,229	(71,229	)	—
Deferred credits and other liabilities		327,307	657		327,964
Retained earnings		3,284,391	65,441		3,349,832
Accumulated other comprehensive income		128,843	3,156		131,999
Total stockholders’ equity		4,052,676	68,597		4,121,273

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles Adopted (Contd.)


	Three Month Period June 30, 2006					Six Month Period June 30, 2006
(Thousands of dollars)	As Previously Reported		FSP AUG AIR-1 Adjustment		As Adjusted	As Previously Reported		FSP AUG AIR-1 Adjustment		As Adjusted
Consolidated Statement of Income
Operating expenses	$	282,830	(3,288	)	279,542	514,994		(6,585	)	508,409
Selling and general expenses		46,559	(11	)	46,548	87,031		(108	)	86,923
Income before income taxes		291,829	3,299		295,128	503,243		6,693		509,936
Income tax expense		77,754	1,200		78,954	175,296		2,483		177,779
Net income		214,075	2,099		216,174	327,947		4,210		332,157
Net income per share:
Basic		1.15	0.01		1.16	1.76		0.03		1.79
Diluted		1.13	0.01		1.14	1.73		0.03		1.76

Consolidated Statement of Cash Flows
Operating Activities
Net income						327,947		4,210		332,157
Provisions for/amortization of major repair costs						15,325		(6,693	)	8,632
Expenditures for major repairs and asset retirements						(10,624	)	8,099		(2,525	)
Deferred and noncurrent income tax charge (benefit)						(22,104	)	2,483		(19,621	)
Net cash provided by operating activities						184,050		8,099		192,149

Investing Activities
Expenditures for major repairs						—		(8,099	)	(8,099	)
Net cash required by investing activities						(604,421	)	(8,099	)	(612,520	)

Uncertain Income Tax Positions

Effective January 1, 2007, the Company adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). This interpretation clarifies the criteria for recognizing income tax benefits under FASB Statement No. 109, Accounting for Income Taxes, and requires additional disclosures about uncertain tax positions. Under FIN 48 the financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon audit by the applicable taxing authority. If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50 percent likely of being realized upon ultimate settlement. Upon adoption of FIN 48 on January 1, 2007, the Company recognized a $0.7 million increase in its liability for unrecognized income tax benefits, which is included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheet, and it recognized a similar decrease to Retained Earnings. A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the six-month period ended June 30, 2007 is as follows:


(Thousands of dollars)	2007
Balance at January 1, 2007	$	21,998
Additions for tax positions of prior years		1,368
Additions for tax positions related to 2007		1,549
Reductions for tax positions of prior years		—
Settlements		—
Changes due to translation of foreign currencies		456

Balance at June 30, 2007	$	25,371

All additions or reductions to the above liability affect the Company’s effective income tax rate in the respective period of change. The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense. The liability for uncertain income taxes as of the date of adoption (January 1, 2007) and June 30, 2007 includes interest and penalties of $5.5 million and $7.4 million, respectively. Income tax expense for the six-month period ended June 30, 2007 included interest and penalties of $1.4 million associated with uncertain tax positions.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles Adopted (Contd.)

During the next year, the Company currently expects the liability for uncertain taxes to increase by amounts that are consistent with the increase that occurred during the six-month period ended June 30, 2007. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. As of June 30, 2007, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2003; Canada – 2001; United Kingdom – 2005; Malaysia – 2004; and Ecuador – 2000.

Retirement and Postretirement Plans Measurement

In September 2006, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of SFAS Nos. 87, 88, 106 and 132R. This statement requires the Company to recognize in its consolidated balance sheet the overfunded or underfunded status of its defined benefit plans as an asset or liability and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. This statement also requires that the Company measure the funded status of all plans as of December 31 rather than September 30 as previously permitted. The Company recognized the funded status position portion of this statement in its Consolidated Balance Sheet as of December 31, 2006. The Company has decided to adopt the requirement to use a December 31 measurement date for defined benefit plan measurement beginning in 2007. The transition from a measurement date as of September 30 to December 31 beginning in 2007 required the Company to reduce its consolidated Retained Earnings as of January 1, 2007 by $4.3 million to recognize the one-time after-tax effect of an additional three months of net periodic benefit expense for its retirement and postretirement benefit plans. The balance sheet adjustments as of January 1, 2007 were as follows:


(Thousands of dollars)	Increase (Decrease)
Deferred income taxes payable	$	(1,708	)
Deferred credits and other liabilities		4,664
Retained earnings		(4,301	)
Accumulated other comprehensive income		1,345

Note C – Property, Plant and Equipment

The FASB Staff Position (FSP) 19-1 applies to companies that use the successful efforts method of accounting and it clarifies that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

At June 30, 2007, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $327.3 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2007 and 2006.


(Thousands of dollars)	2007			2006
Beginning balance at January 1	$	315,445		275,256
Additions pending the determination of proved reserves		19,063		115,417
Reclassifications to proved properties based on the determination of proved reserves		(7,168	)	—

Balance at June 30	$	327,340		390,673

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling.


(Thousands of dollars)	2007		2006
Exploratory well costs capitalized for one year or less	$	45,443	139,063
Capitalized exploratory well costs capitalized for more than one year		281,897	251,610

Balance at June 30	$	327,340	390,673

Number of projects that have exploratory well costs that have been capitalized for more than one year		11	12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Property, Plant and Equipment (Contd.)

On April 30, 2007, the Company entered into an agreement with Wal-Mart Stores, Inc. to purchase parcels of property leased from Wal-Mart for its Murphy USA retail gasoline stations. The purchases will occur during 2007 and 2008 with expected total capital expenditures of approximately $315 million. In conjunction with this agreement, the Company closed 55 stations in the U.S. and Canada. In the Consolidated Statements of Income for the three-month and six-month periods ended June 30, 2007, the Company recorded noncash charges of $40.7 million primarily for impairment of these retail gasoline stations in the U.S. and Canada. The charge includes writedown of remaining undepreciated book value of the station improvements as well as costs of abandonment.

Note D – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2007 and 2006.


	Three Months Ended June 30,
	2007			2006		2007		2006
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	2,759		2,813		537		566
Interest cost		6,268		5,690		1,024		1,006
Expected return on plan assets		(5,605	)	(5,421	)	—		—
Amortization of prior service cost		350		395		(62	)	(69	)
Amortization of transitional asset		(121	)	(162	)	—		—
Recognized actuarial loss		1,451		1,639		373		446

Net periodic benefit expense	$	5,102		4,954		1,872		1,949


	Six Months Ended June 30,
	2007			2006		2007		2006
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	5,443		5,472		1,074		1,132
Interest cost		12,272		11,018		2,048		2,012
Expected return on plan assets		(10,951	)	(10,452	)	—		—
Amortization of prior service cost		696		762		(124	)	(138	)
Amortization of transitional asset		(234	)	(318	)	—		—
Recognized actuarial loss		2,840		3,166		746		892

Net periodic benefit expense	$	10,066		9,648		3,744		3,898

Murphy expects to contribute $10.6 million to its defined benefit pension plans and $4.2 million to its postretirement benefits plan during 2007. During the six-month period ended June 30, 2007, the Company made combined contributions of $3.6 million, and remaining funding in 2007 for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $11.2 million.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Financing Arrangements

In June 2007, Murphy and certain wholly-owned subsidiaries extended by one year and increased the borrowing capacity of its five year committed credit facility with a major banking consortium. Borrowing capacity under the facility is as follows:


June 2007 through June 2010	$	1.962 billion
June 2010 through June 2011	$	1.905 billion
June 2011 through June 2012	$	1.828 billion

Note F – Incentive Plans

SFAS No. 123R, Share Based Payment, requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest. The Company adopted SFAS No. 123R on January 1, 2006. Prior to 2006, the Company used APB No. 25 to account for stock-based compensation.

At the annual meeting of shareholders on May 9, 2007, two new incentive compensation plans were approved and the Employee Stock Purchase Plan was amended. The 2007 Annual Incentive Plan (2007 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees. Cash awards under the 2007 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2007 Long-Term Plan expires in 2017. A total of 6,700,000 shares are issuable during the life of the 2007 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding. The Employee Stock Purchase Plan was amended to increase the number of shares authorized to be issued under the plan from 600,000 to 980,000, and to extend the term of the plan through June 30, 2017.

The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.

Upon approval by shareholders, the 2007 Long-Term Plan replaced the 1992 Stock Incentive Plan (1992 Plan). The 1992 Plan authorized the Committee to make annual grants of the Company’s Common Stock to executives and other key employees in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), and/or restricted stock. Annual grants could not exceed 1% of shares outstanding at the end of the preceding year; allowed shares not granted may be granted in future years.

Cash received from options exercised under all share-based payment arrangements for the six-month periods ended June 30, 2007 and 2006 was $20.8 million and $11.1 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $12.5 million and $6.1 million for the six-month periods ended June 30, 2007 and 2006, respectively.

In February 2007, the Committee granted 895,500 shares of stock options at an exercise price of $51.07 per share. The Black-Scholes valuation for these awards was $15.02 per share. The Committee also issued 299,000 shares of performance-based restricted stock units in February 2007 under the 2007 Long-Term Plan approved by shareholders on May 9, 2007. For accounting purposes the units were considered granted and outstanding on the date the 2007 Plan was approved by shareholders. The fair value of these performance-based restricted stock units, using a Monte Carlo valuation model, was $47.10 per share. Also in February the Committee granted 32,750 shares of time-lapse restricted stock to the Company’s Directors under the 2003 Director Plan. These shares vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the fair market value of the Company’s stock on the date of grant, which was $50.95 per share.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2007 and 2006. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	2007	2006	2007	2006
Basic method	187,615,633	185,919,897	187,361,136	185,813,948
Dilutive stock options	2,545,356	3,181,338	2,593,278	3,233,679

Diluted method	190,160,989	189,101,235	189,954,414	189,047,627

Certain options to purchase shares of common stock were outstanding during the 2007 and 2006 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included options for 1,548,929 shares at a weighted average share price of $53.70 in each 2007 period and 787,500 shares at a weighted average share price of $57.32 in each 2006 period.

Note H – Financial Instruments and Risk Management

Murphy periodically utilizes derivative instruments to manage certain risks related to interest rates, commodity prices, and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.

•

Crude Oil Purchase Price Risks – The Company purchases crude oil as feedstock at its U.S. and U.K. refineries and is therefore subject to commodity price risk. Short-term derivative instruments were outstanding at June 30, 2007 to manage the purchase price of about 1.2 million barrels of crude oil at the Company’s Meraux, Louisiana refinery. The total impact of marking these contracts to market was a charge of $1.9 million in the six-month period ended June 30, 2007.

•

Natural Gas Fuel Price Risks – The Company purchases natural gas as fuel at its Meraux, Louisiana and Superior, Wisconsin refineries, and as such, is subject to commodity price risk related to the purchase price of this gas. Murphy hedged the cash flow risk associated with the cost of a portion of the natural gas it purchased at Meraux in 2006 by entering into financial contracts known as natural gas swaps covering notional volumes of 2,000 MMBTU (million British Thermal Units) per day in 2006. Under the natural gas swaps, the Company paid a fixed rate averaging $3.35 per MMBTU and received a floating rate in each month of settlement based on the average NYMEX price for the final three trading days of the month. The fair value of the effective portions of the natural gas swaps and changes thereto is deferred in AOCI and is subsequently reclassified into Crude Oil and Product Purchases in the income statements in the periods in which the hedged natural gas fuel purchases affect earnings. During the six-month period ended June 30, 2006, the Company received approximately $1.6 million for maturing swap agreements. For the six-month period ended June 30, 2006, the income effect from cash flow hedging ineffectiveness for these contracts was insignificant. There were no forecasted natural gas purchases hedged during 2007.

•

Crude Oil Sales Price Risks – The sales price of crude oil produced by the Company is subject to commodity price risk. Murphy hedged the cash flow risk associated with the sales price for a portion of its Canadian heavy oil production during 2006 by entering into forward sale contracts covering a notional volume of approximately 4,000 barrels per day in 2006. The Company paid the average of the posted price for blended heavy oil at the Hardisty terminal in Canada for each month and received at that location a fixed price of $25.23 per barrel in 2006. The fair values of the effective portions of the crude oil hedges and changes thereto are deferred in AOCI and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affect earnings. During the six-month period ended June 30, 2006, cash flow hedging ineffectiveness relating to the crude oil sales contracts was insignificant. During the six-month period ended June 30, 2006, the Company paid approximately $14.1 million for settlement of maturing forward sale contracts. The fair value of the crude oil sales contracts are based on the average fixed price of the instruments and the published NYMEX index futures price or crude oil price quotes from counterparties. There were no forecasted sales of crude oil hedged during 2007.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at June 30, 2007 and December 31, 2006 are presented in the following table.


(Thousands of dollars)	June 30, 2007			Dec. 31, 2006
Foreign currency translation gains, net of tax	$	334,252		224,894
Retirement and postretirement benefit plan adjustments, net of tax		(85,523	)	(92,895	)

Accumulated other comprehensive income	$	248,729		131,999

The effect of SFAS Nos. 133/138, Accounting for Derivative Investments and Hedging Activities, increased AOCI for the six months ended June 30, 2006 by $0.1 million, net of $0.5 million in income taxes, and hedging ineffectiveness was not significant.

Note J – Hurricane and Insurance Related Matters

In the six-month period ended June 30, 2006, the Company recorded pretax expenses, net of anticipated insurance recoveries, of $78.8 million associated with hurricanes that occurred in the United States in 2005, including $77.5 million at the Meraux refinery. The components of these refinery costs included $39.5 million for repair costs not expected to be recovered due to certain coverage limits for the Company’s insurance policies, $5.9 million for incremental insurance costs, $7.1 million for other uninsured incremental expenses incurred, and $25.0 million for depreciation and salaries for the temporarily idled refinery. The costs are reported in Net Costs Associated with Hurricanes in the Consolidated Statement of Income. See Note K for additional information regarding environmental and other contingencies relating to Hurricane Katrina. Total amounts receivable from insurers for hurricane-related matters was $93.6 million at June 30, 2007, including $29.5 million related to oil spill payments and $64.1 million related to property damage incurred as a result of Hurricane Katrina. Approximately $25 million of the amounts receivable from insurers was not anticipated to be collected in the next twelve months, and has therefore been classified as a noncurrent asset.

The Company maintains insurance coverage related to losses of production and profits for occurrences such as storms, fires and other issues. During the six-month periods ended June 30, 2007 and 2006, the Company received insurance proceeds of $2.0 million and $15.7 million, respectively, related to loss of production in the Gulf of Mexico associated with hurricanes in prior years. These amounts were recorded in Sales and Other Operating Revenues in the respective Consolidated Statements of Income.

Note K – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

In addition to being subject to numerous laws and regulations intended to protect the environment and/or impose remedial obligations, the Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in the Company’s operations. The Company operates or has previously operated certain sites and facilities, including three refineries, five terminals, and approximately 70 service stations for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation, which is generally provided for by the Company’s asset retirement obligation.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Environmental and Other Contingencies (Contd.)

The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount.

The U.S. Environmental Protection Agency (EPA) currently considers the Company a Potentially Responsible Party (PRP) at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently available information, the Company believes that it is a de minimis party as to ultimate responsibility at both Superfund sites. The Company has not recorded a liability for remedial costs on Superfund sites. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the two Superfund sites will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

On September 9, 2005, a class action lawsuit was filed in federal court in the Eastern District of Louisiana seeking unspecified damages to the class comprised of residents of St. Bernard Parish caused by a release of crude oil at Murphy Oil USA, Inc.’s (a wholly-owned subsidiary of Murphy Oil Corporation) Meraux, Louisiana, refinery as a result of flood damage to a crude oil storage tank following Hurricane Katrina. Additional class action lawsuits were consolidated with the first suit into a single action in the U.S. District Court for the Eastern District of Louisiana. In September 2006, the Company reached a settlement with class counsel and on October 10, 2006, the court granted preliminary approval of a class action Settlement Agreement. A Fairness Hearing was held January 4, 2007 and the court entered its ruling on January 30, 2007 approving the class settlement. The majority of the settlement of $330 million will be paid by insurance. The Company recorded an expense of $18 million in the second half of 2006 related to settlement costs not expected to be covered by insurance. As part of the settlement, all properties in the class area will receive a fair and equitable cash payment and will have residual oil removed. As part of the settlement, the Company will offer to purchase all properties in an agreed area adjacent to the west side of the Meraux refinery; these property purchases and associated remediation will be paid by the Company and are expected to total $55 million. Approximately 75 non-class action suits regarding the oil spill have been filed and remain pending. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. Accordingly, the Company believes the ultimate resolution of the remaining litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. The St. Bernard Parish action has since been removed to federal court where a class certification hearing is scheduled for August 28, 2007. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the class action lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Environmental and Other Contingencies (Contd.)

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At June 30, 2007, the Company had contingent liabilities of $8.5 million under a financial guarantee and $127.4 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

Note L – Accounting Matters

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). This pronouncement permits companies with eligible financial assets and financial liabilities to measure these items at fair value in the financial statements. This option to measure at fair value is both instrument specific and irrevocable. If the fair value option is elected, certain additional disclosures are required. This pronouncement is effective in fiscal years beginning after November 15, 2007, but early adoption at the beginning of an earlier fiscal year is permitted as long as adoption occurs before any interim financial statements have been issued for the earlier fiscal year. If the fair value option is elected, financial statements for periods prior to the adoption may not be restated. The Company is in the early stages of considering SFAS No. 159, and the Company is unable to predict at this time whether the fair value option will be elected, and if so, how this decision would effect its consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, and where applicable simplifies and codifies related guidance within GAAP and does not require any new fair value measurements. The Statement is effective for fiscal years beginning January 1, 2008. Provisions of the Statement are to be applied prospectively except in limited situations. The Company does not expect the initial adoption of this Statement to have a material impact on its financial statements.

In June 2007, the FASB ratified the Emerging Issues Task Force’s Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. This new guidance will be effective for the Company beginning in 2008, and will require that income tax benefits received by the Company for dividends paid on share-based incentive awards be recorded in Capital in Excess of Par Value in Stockholders’ Equity. Under certain circumstances, such tax benefits received on awards that do not vest could be reclassified to reduce income tax expense in the Consolidated Statements of Income. The Company does not expect the adoption of this consensus to have a material impact on its financial statements.

In October 2004, the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”) became law. The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that provides a tax deduction on qualified production activities. The tax deduction phased in at 3% beginning in 2005, increased to 6% in 2007 and increases again to 9% in 2010. FSP 109-1 concluded that the tax benefits for the deduction should be recognized as realized. This FSP was effective upon issuance and the Company applied it in computing U.S. income tax beginning in 2005. The Company recorded tax benefits of approximately $3.2 million and $0.7 million in the six-month periods ended June 30, 2007 and 2006, respectively, related to the Act.

Note M – Commitments

In the first six months of 2007, the Company entered into contracts for drilling rigs and associated equipment for periods beyond June 30, 2007. The rigs are to be utilized for drilling operations in Malaysia and the United States. The commitments, which expire in 2010 through 2012, total approximately $959 million. A portion of these costs will be borne by other working interest owners when the wells are drilled. These drilling costs are expected to be accounted for as capital expenditures as incurred during the contract periods.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N – Income Taxes

The three-month and six-month periods of both 2007 and 2006 include income tax benefits related to enacted Canadian Federal and/or provincial tax rate reductions. Such benefits were $4.8 million in both 2007 periods and $37.5 million in both 2006 periods.

Note O – Business Segments


	Total Assets at June 30, 2007		Three Mos. Ended June 30, 2007					Three Mos. Ended June 30, 2006¹
(Millions of dollars)	Total Assets at June 30, 2007		External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production²
United States	$	969.1	104.7		—	23.8		177.4	—	67.8
Canada		2,030.8	218.1		22.0	91.0		179.7	32.2	114.3
United Kingdom		186.7	45.3		—	14.8		69.1	—	32.5
Malaysia		1,703.1	48.8		—	15.1		67.1	—	21.9
Ecuador		144.7	37.1		—	9.9		42.7	—	13.4
Other		250.4	.8		—	(5.3	)	.9	—	(4.8	)

Total		5,284.8	454.8		22.0	149.3		536.9	32.2	245.1

Refining and marketing
North America		2,126.0	3,871.7		—	107.2		2,972.6	—	(24.7	)
United Kingdom		387.6	288.5		—	17.0		287.5	—	13.6

Total		2,513.6	4,160.2		—	124.2		3,260.1	—	(11.1	)

Total operating segments		7,798.4	4,615.0		22.0	273.5		3,797.0	32.2	234.0
Corporate		790.3	(1.4	)	—	(23.2	)	1.9	—	(17.8	)

Total	$	8,588.7	4,613.6		22.0	250.3		3,798.9	32.2	216.2


	Six Months Ended June 30, 2007					Six Months Ended June 30, 2006¹
(Millions of dollars)	External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production²
United States	$	198.6	—	34.5		375.3	—	154.2
Canada		397.5	45.1	156.5		357.5	47.3	182.6
United Kingdom		82.8	—	26.9		121.9	—	56.7
Malaysia		92.9	—	24.9		121.1	—	5.0
Ecuador		62.5	—	14.0		69.1	—	21.1
Other		1.9	—	(18.7	)	2.1	—	(12.6	)

Total		836.2	45.1	238.1		1,047.0	47.3	407.0

Refining and marketing
North America		6,692.2	—	141.7		5,234.3	—	(60.3	)
United Kingdom		514.6	—	18.2		502.8	—	13.6

Total		7,206.8	—	159.9		5,737.1	—	(46.7	)

Total operating segments		8,043.0	45.1	398.0		6,784.1	47.3	360.3
Corporate		5.5	—	(37.1	)	6.1	—	(28.1	)

Total	$	8,048.5	45.1	360.9		6,790.2	47.3	332.2

¹	Results for 2006 have been adjusted to reflect the adoption of FSP AUG AIR-1, Accounting for Planned Major Maintenance Activities.

²	Additional details about results of oil and gas operations are presented in the tables on page 21 and 22.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Results of Operations

Murphy’s net income in the second quarter of 2007 was $250.3 million, $1.32 per diluted share, compared to net income of $216.2 million, $1.14 per diluted share, in the second quarter of 2006. The higher income in 2007 primarily related to improved earnings in the Company’s refining and marketing operations, but this was partially offset by lower earnings in the exploration and production business and higher net costs for corporate activities. Net income in the second quarter 2007 included after-tax costs of $24.0 million for closure of 55 retail gasoline stations in the U.S. and Canada. Both periods included non-cash income tax benefits related to enacted Canadian income tax rate reductions, and these amounted to $4.8 million in the 2007 period and $37.5 million in the 2006 period. The 2006 second quarter results have been adjusted to reflect the adoption of FASB Staff Position No. AUG AIR-1, Accounting for Planned Major Maintenance Activities. Net income in the second quarter 2006 increased by $2.1 million for this change in accounting principle.

For the first six months of 2007, net income totaled $360.9 million, $1.90 per diluted share, compared to net income of $332.2 million, $1.76 per diluted share, for the same period in 2006. The higher six-month income in 2007 compared to 2006 was primarily attributable to strong earnings in the 2007 period for the North American refining and marketing segment, while results in the 2006 period reflected losses in this segment as the Meraux refinery was not operating for a portion of the quarter following Hurricane Katrina and was incurring repair costs that exceeded available insurance recoveries. The adoption of FASB Staff Position No. AUG AIR-1 increased the six-month 2006 net income by $4.2 million.

Murphy’s net income by operating segment is presented below.


	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2007			2006		2007		2006
Exploration and production	$	149.3		245.1		238.1		407.0
Refining and marketing		124.2		(11.1	)	159.9		(46.7	)
Corporate		(23.2	)	(17.8	)	(37.1	)	(28.1	)

Net income	$	250.3		216.2		360.9		332.2

In the 2007 second quarter, the Company’s exploration and production operations earned $149.3 million, compared to $245.1 million in the 2006 quarter. Income in both 2007 and 2006 quarters included non-cash Canadian income tax benefits, which amounted to $4.8 million and $37.5 million, respectively. Income in the 2007 quarter was unfavorably affected by lower crude oil and natural gas sales volumes compared to 2006, but benefited from higher oil and natural gas sales prices. Exploration expenses were $30.1 million in the second quarter of 2007 compared to $30.2 million in the same period of 2006 as higher dry hole costs were offset by lower geological and geophysical costs. The Company’s refining and marketing operations generated income of $124.2 million in the 2007 second quarter compared to a loss of $11.1 million in the same quarter of 2006. North American refining and marketing margins were strong in the second quarter 2007, and the Meraux refinery operated throughout the 2007 quarter. Income for the United Kingdom downstream business also improved in the 2007 second quarter compared to the same period in 2006 mostly due to stronger refining margins. The after-tax costs of the corporate function were $23.2 million in the 2007 second quarter compared to $17.8 million in the 2006 period with the cost increase due to unfavorable foreign currency exchange effects and higher administrative costs in 2007.

Net income was $360.9 million in the first six months of 2007 compared to $332.2 million in the same 2006 period. The Company’s exploration and production operations earned $238.1 million in the first half of 2007 compared to $407.0 million in the same period of 2006. Earnings in 2007 benefited from slightly higher realized oil prices, but were unfavorably affected by lower oil and natural gas sales volumes and lower North American natural gas sales prices. Both six-month periods included non-cash Canadian income tax benefits, including $4.8 million in 2007 and $37.5 million in 2006, and the 2006 period included $15.7 million of pretax income from insurance proceeds related to Gulf of Mexico production lost in the fourth quarter 2005 following Hurricane Katrina. The Company’s refining and marketing operations had earnings of $159.9 million in the first six months of 2007, compared to a loss of $46.7 million in the same 2006 period. The 2007 period included stronger results in the North American downstream business compared to a year ago and income from downstream operations in the U.K. improved in 2007 compared to 2006 due to better margins in both refining and marketing operations. Corporate after-tax costs were $37.1 million in the 2007 period compared to costs of $28.1 million in the 2006 period. Unfavorable foreign currency exchange results and higher administrative expenses accounted for most of the higher net costs in 2007.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production

Results of exploration and production operations are presented by geographic segment below.


	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2007			2006		2007		2006
Exploration and production
United States	$	23.8		67.8		34.5		154.2
Canada		91.0		114.3		156.5		182.6
United Kingdom		14.8		32.5		26.9		56.7
Malaysia		15.1		21.9		24.9		5.0
Ecuador		9.9		13.4		14.0		21.1
Other International		(5.3	)	(4.8	)	(18.7	)	(12.6	)

Total	$	149.3		245.1		238.1		407.0

Exploration and production operations in the United States reported quarterly earnings of $23.8 million in the second quarter of 2007 compared to earnings of $67.8 million in the 2006 quarter. Earnings were lower in the 2007 period due mostly to lower oil and natural gas production volumes. A higher average natural gas sales price in 2007 compared to 2006 was mostly offset by a lower average sales price for crude oil and condensate. Production and depreciation expenses in the 2007 period were less than 2006 due to lower crude oil and natural gas sales volumes. Exploration expenses in the 2007 period increased $2.9 million from the prior year primarily due to higher dry hole costs, somewhat offset by lower geological and geophysical expenses.

Operations in Canada earned $91.0 million in the second quarter 2007 compared to $114.3 million in the 2006 quarter. The current quarter includes $4.8 million in non-cash income tax benefits related to a Federal tax rate reduction enacted in the 2007 quarter, but this was $32.7 million less than the tax benefits recorded from more significant Federal and provincial tax rate reductions enacted in the 2006 second quarter. Excluding these income tax benefits in both periods, Canadian earnings improved in the 2007 quarter versus the same period a year ago, mostly due to higher sales volumes from the Terra Nova oil field and at Syncrude. Terra Nova was shut down for about half of the 2006 second quarter following mechanical equipment failure. The 2007 second quarter had higher natural gas sales prices, but the period also included higher geophysical expenses compared to the 2006 quarter.

United Kingdom operations earned $14.8 million in the 2007 quarter, down from $32.5 million in the 2006 quarter. The decline was primarily due to lower crude oil and natural gas sales volumes in the 2007 quarter compared to 2006. In addition, the current quarter included lower crude oil and natural gas sales prices, higher production expenses, and a higher tax rate. The current effective tax rate of 50% was increased by 10% beginning in the third quarter of 2006.

Operations in Malaysia reported earnings of $15.1 million in the 2007 quarter compared to income of $21.9 million during the same period in 2006. The earnings reduction in 2007 in Malaysia was primarily due to lower crude oil sales volumes and higher production expenses in the current period, partially offset by lower geophysical expenses.

Operations in Ecuador earned $9.9 million in the second quarter of 2007 compared to $13.4 million in the 2006 period. The 2007 period results were lower than 2006 primarily due to higher sales volumes in the prior-year quarter, which included 9,375 barrels per day for settlement of crude oil production volumes owed to the Company by two partners since 2004. This lower volume of oil sales was only partially offset by higher oil sales prices in 2007.

Other international operations reported a loss of $5.3 million in the second quarter of 2007 compared to a loss of $4.8 million in the 2006 period. Higher geophysical expenses in the Republic of Congo and Suriname were the primary causes of the unfavorable variance.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $57.19 per barrel in the second quarter 2007 compared to $54.10 in the 2006 period. Average crude oil and liquids production was 79,949 barrels per day in the second quarter of 2007 compared to 90,695 barrels per day in the second quarter of 2006, with the decrease primarily attributable to a combination of lower production in the deepwater Gulf of Mexico, the heavy oil

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

area of Western Canada, offshore United Kingdom and the West Patricia field offshore Sarawak, Malaysia. Oil production improved in 2007 offshore Eastern Canada at the Terra Nova field, which was shut down for half the 2006 quarter following mechanical equipment failure. Oil production at Syncrude increased in the 2007 period compared to 2006 due to start-up of the third coker unit, and oil production increased in Ecuador due to a development drilling program. Crude oil sales volumes averaged 83,629 barrels per day in the second quarter 2007 compared to 103,360 barrels per day in the 2006 period. The previously mentioned oil settlement with partners in Ecuador added sales volume of 9,375 barrels per day in the 2006 quarter. The remaining portion of lower crude oil sales volumes was essentially in line with lower oil production volumes. North American natural gas sales prices averaged $8.02 per thousand cubic feet (MCF) in the most recent quarter compared to $7.10 per MCF in the same quarter of 2006. Natural gas sales volumes averaged 56 million cubic feet per day in the second quarter 2007, down from 87 million cubic feet per day in the 2006 quarter, primarily due to production declines at fields in the deepwater Gulf of Mexico and onshore South Louisiana.

Operations in the United States for the six months ended June 30, 2007 produced income of $34.5 million compared to income of $154.2 million in the 2006 period. The 2007 period had lower crude oil and natural gas sales volumes, lower oil and natural gas sales prices, lower income associated with insurance proceeds, and higher workover and exploration expenses. In the 2006 period, the Company received $15.7 million of pretax insurance proceeds related to Gulf of Mexico production lost in the fourth quarter of 2005 following Hurricane Katrina. Exploration expenses in the 2007 period were $12.0 million higher than 2006 mostly due to more dry holes expense, but partially offset by lower geological and geophysical expenses.

In the first half of 2007, Canadian operations earned $156.5 million compared to $182.6 million a year ago. The 2007 period included lower income tax benefits from enacted tax rate reductions of $32.7 million. Higher sales volumes for crude oil and natural gas were mostly offset by lower natural gas sales volumes, lower sales prices for oil and natural gas, and higher depreciation expense.

Income in the U.K. for the six-month period in 2007 was $26.9 million compared to $56.7 million a year ago with the decline primarily due to lower crude oil and natural gas sales volumes and lower realized oil and natural gas sales prices. In addition, the effective income tax was 10% higher in the 2007 period due to a tax rate increase enacted in the third quarter of 2006.

Malaysia operations earned $24.9 million in the first half of 2007 compared to earnings of $5.0 million in the 2006 period. The earnings improvement was primarily caused by lower dry hole, geophysical and depreciation expenses in the current period. Earnings in 2007 were unfavorably effected by lower crude oil sales volumes and prices.

For the first six months of 2007, earnings in Ecuador were $14.0 million compared to $21.1 million for the 2006 period. The earnings decline in 2007 was due to lower crude oil sales volumes and higher production and depreciation expenses, partially offset by a higher realized oil sales price.

Other international operations reported a loss of $18.7 million in the first six months of 2007 compared to a loss of $12.6 million in the 2006 period. The larger loss in the 2007 period was primarily due to higher geophysical expenses in the Republic of Congo.

For the first six months of 2007, the Company’s sales price for crude oil and condensate averaged $52.45 per barrel compared to $51.67 per barrel in 2006. Crude oil, condensate and gas liquids production in the first half of 2007 averaged 82,241 barrels per day compared to 94,365 barrels per day a year ago. The decrease was mostly attributable to lower production at fields in the deepwater Gulf of Mexico, the heavy oil area of Western Canada, and at West Patricia, offshore Malaysia. Oil production volumes in 2007 were higher at Terra Nova and Hibernia, offshore Eastern Canada, due to less downtime at the fields. Oil production increased in the 2007 period compared to 2006 at Syncrude due to start-up of the third coker unit and in Ecuador due to a development drilling program. The average sales price for North American natural gas in the first six months of 2007 was $7.64 per MCF, down from $8.17 per MCF in 2006. Natural gas sales volumes were down from 86 million cubic feet per day in 2006 to 59 million cubic feet per day in 2007, with the decline due mostly to lower sales production volumes from deepwater Gulf of Mexico and onshore South Louisiana fields.

Additional details about results of oil and gas operations are presented in the tables on pages 21 and 22.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month and six-month periods ended June 30, 2007 and 2006 follow.


	Three Months Ended June 30,			Six Months Ended June 30,
	2007		2006	2007	2006
Net crude oil, condensate and gas liquids produced – barrels per day		79,949	90,695	82,241	94,365
United States		13,458	23,421	13,775	24,951
Canada – light		592	426	560	419
– heavy		9,554	13,429	11,224	14,300
– offshore		20,843	13,409	19,666	15,931
– synthetic		11,427	10,898	12,073	10,520
United Kingdom		5,461	8,499	5,887	8,301
Malaysia		9,578	12,229	9,990	11,589
Ecuador		9,036	8,384	9,066	8,354

Net crude oil, condensate and gas liquids sold – barrels per day		83,629	103,360	84,046	102,090
United States		13,458	23,421	13,775	24,951
Canada – light		592	426	560	419
– heavy		9,554	13,429	11,224	14,300
– offshore		21,705	15,645	20,150	17,595
– synthetic		11,427	10,898	12,073	10,520
United Kingdom		6,859	9,896	6,675	8,854
Malaysia		9,885	12,952	9,899	13,271
Ecuador		10,149	16,693	9,690	12,180

Net natural gas sold – thousands of cubic feet per day		56,579	87,466	58,837	85,539
United States		41,879	68,691	42,596	64,159
Canada		8,655	9,435	9,054	9,767
United Kingdom		6,045	9,340	7,187	11,613

Total net hydrocarbons produced – equivalent barrels per day (1)		89,379	105,273	92,047	108,621
Total net hydrocarbons sold – equivalent barrels per day (1)		93,059	117,938	93,852	116,346

Weighted average sales prices –
Crude oil and condensate – dollars per barrel (2)
United States	$	59.39	61.04	54.84	57.38
Canada (3) – light		49.66	64.05	50.40	57.28
– heavy (4)		29.65	32.44	31.18	24.65
– offshore		67.19	67.43	61.43	63.12
– synthetic		69.92	69.16	63.91	64.78
United Kingdom		66.68	69.85	61.59	65.91
Malaysia (5)		55.47	56.81	51.66	53.68
Ecuador (6)		40.14	28.09	35.55	31.33

Natural gas – dollars per thousand cubic feet
United States (2)	$	8.18	7.28	7.76	8.32
Canada (3)		7.22	5.76	7.08	7.17
United Kingdom (3)		6.58	7.15	6.76	7.61

(1)	Natural gas converted on an energy equivalent basis of 6:1

(2)	Includes intracompany transfers at market prices.

(3)	U.S. dollar equivalent.

(4)	Includes the effects of the Company’s hedging program in 2006.

(5)	Prices are net of payments under the terms of the production sharing contract for Block SK 309.

(6)	All prices are net of revenue sharing with the Ecuadorian government that was legislated effective in April 2006, and the second quarter and year-to-date 2006 prices were adversely affected by the settlement with nonoperator partners of crude oil production owed to the Company since 2004.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2007 AND 2006


(Millions of dollars)	United States		Canada		United Kingdom	Malaysia	Ecuador	Other		Synthetic Oil – Canada		Total
Three Months Ended June 30, 2007
Oil and gas sales and other revenues	$	104.7	167.5		45.3	48.8	37.1	.8		72.6		476.8
Production expenses		17.2	26.6		7.3	10.1	9.7	—		29.0		99.9
Depreciation, depletion and amortization		16.7	40.0		6.6	7.5	10.2	.2		6.0		87.2
Accretion of asset retirement obligations		1.0	1.2		.5	.9	—	.1		.1		3.8
Exploration expenses
Dry holes		14.3	(.1	)	—	.1	.1	(.4	)	—		14.0
Geological and geophysical		1.6	1.5		—	.3	—	1.7		—		5.1
Other		3.3	.1		.1	—	—	1.0		—		4.5

		19.2	1.5		.1	.4	.1	2.3		—		23.6
Undeveloped lease amortization		4.4	1.7		—	—	—	.4		—		6.5

Total exploration expenses		23.6	3.2		.1	.4	.1	2.7		—		30.1

Impairment of long-lived assets		2.6	—		—	—	—	—		—		2.6
Selling and general expenses		6.8	4.4		.9	3.0	.3	2.9		.2		18.5

Results of operations before taxes		36.8	92.1		29.9	26.9	16.8	(5.1	)	37.3		234.7
Income tax provisions		13.0	28.4		15.1	11.8	6.9	.2		10.0		85.4

Results of operations (excluding corporate overhead and interest)	$	23.8	63.7		14.8	15.1	9.9	(5.3	)	27.3		149.3


Three Months Ended June 30, 2006
Oil and gas sales and other revenues	$	177.4	143.4		69.1	67.1	42.7	.9		68.5		569.1
Production expenses		21.3	28.4		5.0	9.1	11.0	—		31.5		106.3
Depreciation, depletion and amortization		24.6	24.9		7.8	12.5	9.0	.1		3.8		82.7
Accretion of asset retirement obligations		.7	1.0		.5	—	—	.1		.2		2.5
Exploration expenses
Dry holes		3.5	—		—	.7	—	(.1	)	—		4.1
Geological and geophysical		9.4	(.2	)	—	5.8	—	.1		—		15.1
Other		3.4	.2		.2	—	—	1.6		—		5.4

		16.3	—		.2	6.5	—	1.6		—		24.6
Undeveloped lease amortization		4.4	.9		—	—	—	.3		—		5.6

Total exploration expenses		20.7	.9		.2	6.5	—	1.9		—		30.2

Net costs associated with hurricanes		.8	—		—	—	—	—		—		.8
Selling and general expenses		4.8	2.8		1.1	1.0	.4	3.3		.2		13.6

Results of operations before taxes		104.5	85.4		54.5	38.0	22.3	(4.5	)	32.8		333.0
Income tax provisions (benefits)		36.7	8.6		22.0	16.1	8.9	.3		(4.7	)	87.9

Results of operations (excluding corporate overhead and interest)	$	67.8	76.8		32.5	21.9	13.4	(4.8	)	37.5		245.1

*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; see Note B to the financial statements.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2007 AND 2006


(Millions of dollars)	United States		Canada		United Kingdom	Malaysia	Ecuador	Other		Synthetic Oil – Canada	Total
Six Months Ended June 30, 2007
Oil and gas sales and other revenues	$	198.6	303.0		82.8	92.9	62.5	1.9		139.6	881.3
Production expenses		43.4	46.8		13.2	17.2	18.8	—		60.5	199.9
Depreciation, depletion and amortization		33.4	75.4		12.4	15.8	18.7	.3		11.8	167.8
Accretion of asset retirement obligations		1.8	2.2		1.0	1.6	—	.3		.3	7.2
Exploration expenses
Dry holes		27.5	.9		—	.1	.3	(.4	)	—	28.4
Geological and geophysical		11.4	4.3		—	5.1	—	9.1		—	29.9
Other		3.8	.2		.2	—	—	3.1		—	7.3

		42.7	5.4		.2	5.2	.3	11.8		—	65.6
Undeveloped lease amortization		8.9	3.2		—	—	—	.8		—	12.9

Total exploration expenses		51.6	8.6		.2	5.2	.3	12.6		—	78.5

Impairment of long-lived assets		2.6	—		—	—	—	—		—	2.6
Selling and general expenses		12.3	8.5		1.9	6.8	.5	6.9		.4	37.3

Results of operations before taxes		53.5	161.5		54.1	46.3	24.2	(18.2	)	66.6	388.0
Income tax provisions		19.0	51.9		27.2	21.4	10.2	.5		19.7	149.9

Results of operations (excluding corporate overhead and interest)	$	34.5	109.6		26.9	24.9	14.0	(18.7	)	46.9	238.1


Six Months Ended June 30, 2006
Oil and gas sales and other revenues	$	375.3	281.5		121.9	121.1	69.1	2.1		123.3	1,094.3
Production expenses		36.9	48.2		9.5	17.4	17.6	—		61.7	191.3
Depreciation, depletion and amortization		48.0	54.3		14.5	25.2	14.5	.2		7.3	164.0
Accretion of asset retirement obligations		1.4	2.0		.9	.1	—	.3		.3	5.0
Exploration expenses
Dry holes		6.1	—		—	30.6	1.1	3.4		—	41.2
Geological and geophysical		21.1	(.1	)	—	12.1	—	.7		—	33.8
Other		3.9	.3		.2	.2	—	2.8		—	7.4

		31.1	.2		.2	42.9	1.1	6.9		—	82.4
Undeveloped lease amortization		8.5	1.8		—	—	—	.7		—	11.0

Total exploration expenses		39.6	2.0		.2	42.9	1.1	7.6		—	93.4

Net costs associated with hurricanes		1.3	—		—	—	—	—		—	1.3
Selling and general expenses		10.3	5.3		2.0	3.6	.6	6.1		.4	28.3

Results of operations before taxes		237.8	169.7		94.8	31.9	35.3	(12.1	)	53.6	611.0
Income tax provisions		83.6	38.4		38.1	26.9	14.2	.5		2.3	204.0

Results of operations (excluding corporate overhead and interest)	$	154.2	131.3		56.7	5.0	21.1	(12.6	)	51.3	407.0

*	Adjusted to reflect adoption of FASB Staff Position No. AUG AIR-1; see Note B to the financial statements.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Refining and Marketing

Results of refining and marketing operations are presented below by geographic segment.


	Income (Loss)
	Three Months Ended June 30,				Six Months Ended June 30,
(Millions of dollars)	2007		2006		2007	2006
Refining and marketing
North America	$	107.2	(24.7	)	141.7	(60.3	)
United Kingdom		17.0	13.6		18.2	13.6

Total	$	124.2	(11.1	)	159.9	(46.7	)

The Company’s refining and marketing operations generated income of $124.2 million in the 2007 second quarter compared to a loss of $11.1 million in the same quarter of 2006. North American operations had a profit of $107.2 million in the 2007 period compared to a loss of $24.7 million in 2006. Refining and marketing margins were strong in the second quarter of 2007, and the Company’s Meraux, Louisiana refinery operated throughout the quarter. The Meraux refinery was shut down for repairs following Hurricane Katrina for a portion of the 2006 quarter prior to restarting in May, and the refinery incurred $26.5 million of unrecoverable Hurricane Katrina-related repair costs during the 2006 quarter. The 2007 second quarter included $24.0 million of after-tax charges associated with closure of 55 retail gasoline stations in the U.S. and Canada. Earnings in the United Kingdom were $17.0 million in the second quarter of 2007 compared to earnings of $13.6 million in the same period a year ago. The 2007 quarter benefited from stronger refinery margins at the Company’s jointly-owned Milford Haven, Wales refinery. Worldwide petroleum product sales averaged 439,099 barrels per day in 2007, compared to 363,109 barrels per day in the same period in 2006. The 2007 sales volume increase was attributable to higher U.S. sales volumes from both refining and retail marketing operations. Worldwide refinery inputs were 181,149 barrels per day in the second quarter of 2007 compared to 90,832 in the 2006 quarter. Refinery inputs in 2006 were adversely affected by the Meraux refinery being shut down for repairs until mid-May 2006 following Hurricane Katrina.

Refining and marketing operations in North America in the first half of 2007 generated a profit of $141.7 million compared to a loss of $60.3 million in the 2006 period. Current year results were favorable mostly due to strong refining margins in the 2007 period, while the 2006 period included significant downtime and repair costs at the Meraux refinery following Hurricane Katrina. Meraux incurred $39.5 million of charges during the 2006 six-month period for repair costs which were not expected to be recoverable from insurance. Results in the United Kingdom reflected earnings of $18.2 million in the first six months of 2007 compared to earnings of $13.6 million in the 2006 period. The increase was primarily due to higher refining and marketing margins on sale of petroleum products in 2007.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Refining and Marketing (Contd.)

Selected operating statistics for the three-month and six-month periods ended June 30, 2007 and 2006 follow.


	Three Months Ended June 30,		Six Months Ended June 30,
	2007	2006	2007	2006
Refinery inputs – barrels per day	181,149	90,832	180,542	77,519
North America	145,289	54,904	147,714	44,232
United Kingdom	35,860	35,928	32,828	33,287

Petroleum products sold – barrels per day	439,099	363,109	430,597	349,817
North America	402,720	326,117	395,117	315,313
Gasoline	298,161	262,463	286,505	254,672
Kerosine	209	1,681	1,808	2,955
Diesel and home heating oils	79,559	47,121	83,873	47,155
Residuals	15,897	9,148	15,627	5,937
Asphalt, LPG and other	8,894	5,704	7,304	4,594
United Kingdom	36,379	36,992	35,480	34,504
Gasoline	11,174	12,072	11,667	11,953
Kerosine	3,667	2,796	3,412	3,047
Diesel and home heating oils	11,870	13,117	12,134	11,347
Residuals	3,674	5,103	3,373	4,124
LPG and other	5,994	3,904	4,894	4,033

Corporate and other

The net cost of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, was $23.2 million in the 2007 second quarter compared to $17.8 million in the 2006 quarter with the cost increase due mostly to unfavorable foreign currency exchange effects and higher administrative costs in 2007, but these were partly offset by lower net interest expense after capitalizing amounts to ongoing development projects. In the first six months of 2007, corporate activities reflected a net cost of $37.1 million compared to a net cost of $28.1 million a year ago, and the reasons for the unfavorable cost variance in 2007 relative to 2006 were the same as for the second quarter 2007.

Financial Condition

Net cash provided by operating activities was $683.3 million for the first six months of 2007 compared to $192.1 million during the same period in 2006. Changes in operating working capital other than cash and cash equivalents used cash of $31.5 million in the first six months of 2007 and $393.7 million in the 2006 period. The use of cash in the 2006 period for working capital was mostly attributable to higher accounts receivable from insurance companies related to hurricane-related repairs and clean up at the Meraux refinery.

Other predominant uses of cash in both years were for dividends, which totaled $56.4 million in 2007 and $42.0 million in 2006, and for property additions and dry holes, which, including amounts expensed, were $813.4 million and $610.5 million in the six-month periods ended June 30, 2007 and 2006, respectively. Total capital expenditures were as follows:


	Six Months Ended June 30,
(Millions of dollars)	2007		2006
Capital Expenditures
Exploration and production	$	787.2	555.8
Refining and marketing		98.3	92.5
Corporate and other		2.1	3.4

Total capital expenditures		887.6	651.7

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition (Contd.)

Working capital (total current assets less total current liabilities) at June 30, 2007 was $949.4 million, an increase of $153.4 million from December 31, 2006. This level of working capital does not fully reflect the Company’s liquidity position, because the lower historical costs assigned to inventories under last-in first-out accounting were $514.7 million below fair value at June 30, 2007.

At June 30, 2007, total long-term debt of $1,105.1 million had increased by $264.8 million compared to December 31, 2006. A summary of capital employed at June 30, 2007 and December 31, 2006 follows.


	June 30, 2007			Dec. 31, 2006
(Millions of dollars)	Amount		%	Amount		%
Capital employed
Notes payable	$	1,102.2	19.4	$	833.1	16.8
Nonrecourse debt of a subsidiary		2.9	—		7.2	0.1
Stockholders' equity		4,581.2	80.6		4,121.3	83.1

Total capital employed	$	5,686.3	100.0	$	4,961.6	100.0

The Company’s ratio of earnings to fixed charges was 15.3 to 1 for the six-month period ended June 30, 2007.

Accounting and Other Matters

In October 2004, the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the “Act”) became law. The FASB issued FSP 109-1 in December 2004 to provide guidance on the application of SFAS No. 109, Accounting for Income Taxes, to the provision within the Act that provides a tax deduction on qualified production activities. The tax deduction phased in at 3% beginning in 2005, increased to 6% in 2007 and increases again to 9% in 2010. FSP 109-1 concluded that the tax benefits for the deduction should be recognized as realized. This FSP was effective upon issuance and the Company applied it in computing U.S. income tax beginning in 2005. The Company recorded tax benefits of approximately $0.2 million and $0.3 million in the three-month periods ended March 31, 2007 and 2006, respectively, related to the Act.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Accounting and Other Matters (Contd.)

Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. In 2001, the local tax authorities announced that Value Added Taxes (VAT) paid on goods and services related to Block 16 and many oil fields held by other companies will no longer be reimbursed. In response to this announcement, the operator of Block 16 filed numerous actions in the Ecuador Tax Court seeking determination that the VAT in question is reimbursable. In July 2004, international arbitrators ruled that VAT was recoverable by another oil company, but the State of Ecuador responded that it was not bound by this arbitral decision. As of June 30, 2007, the Company has a receivable of approximately $11.5 million related to VAT. In early 2007, Ecuadorian authorities settled this issue with the Company by agreeing to assign a portion of the government’s future oil volumes to the Block 16 partners. The settlement had no material impact on the Company’s financial position or net income.

Outlook

The Kikeh field development project offshore Sabah Malaysia continues on pace with a targeted production start-up during the third quarter 2007. Crude oil prices in July 2007 have been higher than the average during the second quarter 2007, and the Company expects its oil and natural gas production to average about 92,000 barrels of oil equivalent per day in the quarter. U.S. refining margins have weakened during July due to higher crude oil feedstock prices. The Company currently anticipates total capital expenditures for the full year 2007 will be approximately $2.3 billion, including Wal-Mart site purchases addressed in Note C of the consolidated financial statements.

Forward-Looking Statements

This Form 10-Q report contains statements of the Company’s expectations, intentions, plans and beliefs that are forward-looking and are dependent on certain events, risks and uncertainties that may be outside of the Company’s control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results and developments could differ materially from those expressed or implied by such statements due to a number of factors including those described in the context of such forward-looking statements as well as those contained in the Company’s January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange Commission.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note H to this Form 10-Q report, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. There were short-term derivative contracts in place at June 30, 2007 to hedge the purchase price of about 1.2 million barrels of crude oil at the Meraux refinery. A 10% increase in the price of West Texas Intermediate crude oil would have increased the liability associated with this derivative contract by approximately $3.7 million, while a 10% decrease would have reduced the liability by a similar amount.

ITEM 4.

CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

ITEM 4.

CONTROLS AND PROCEDURES (Contd.)

There were no changes in the Company’s internal control over financial reporting during the quarter ended June 30, 2007 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

On September 9, 2005, a class action lawsuit was filed in federal court in the Eastern District of Louisiana seeking unspecified damages to the class comprised of residents of St. Bernard Parish caused by a release of crude oil at Murphy Oil USA, Inc.’s (a wholly-owned subsidiary of Murphy Oil Corporation) Meraux, Louisiana, refinery as a result of flood damage to a crude oil storage tank following Hurricane Katrina. Additional class action lawsuits were consolidated with the first suit into a single action in the U.S. District Court for the Eastern District of Louisiana. In September 2006, the Company reached a settlement with class counsel and on October 10, 2006, the court granted preliminary approval of a class action Settlement Agreement. A Fairness Hearing was held January 4, 2007 and the court entered its ruling on January 30, 2007 approving the class settlement. The majority of the settlement of $330 million will be paid by insurance. The Company recorded an expense of $18 million in the second half of 2006 related to settlement costs not expected to be covered by insurance. As part of the settlement, all properties in the class area will receive a fair and equitable cash payment and will have residual oil cleaned. As part of the settlement, the Company will offer to purchase all properties in an agreed area adjacent to the west side of the Meraux refinery; these property purchases and associated remediation will be paid by the Company and are expected to total $55 million. Approximately 75 non-class action suits regarding the oil spill have been filed and remain pending. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. Accordingly, the Company believes the ultimate resolution of the remaining litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

PART II – OTHER INFORMATION (Contd.)

ITEM 1A.

RISK FACTORS

In addition to the risk factors previously disclosed in its Form 10-K filed on March 1, 2007, the Company’s proved undeveloped reserves and non-producing proved developed reserves represent significant portions of total proved reserves. As of December 31, 2006, approximately 43% of the Company’s proved oil reserves and 79% of proved natural gas reserves are undeveloped. The ability of the Company to reclassify these undeveloped proved reserves to the proved developed classification is generally dependent on the successful completion of one or more operations, which might include further development drilling, construction of facilities or pipelines, and well workovers. Proved undeveloped reserves have inherently more risk than proved developed reserves, generally due to significant development work which is both costly and uncertain as to timing of completion prior to the start of production. Also, at December 31, 2006, the Company’s non-producing proved developed reserves represent approximately 9% of the Company’s total proved reserves on a barrel of oil equivalent basis. These non-producing proved developed reserves are primarily in the U.S. Gulf of Mexico and generally represent “behind pipe” reserves that will require an uphole recompletion to produce the more shallow oil or natural gas reservoir. These “behind pipe” reserves have more risk than producing proved developed reserves.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the annual meeting of security holders on May 9, 2007, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below.


	For	Withheld
Frank W. Blue	158,997,996	1,728,308
Claiborne P. Deming	158,801,151	1,925,153
Robert A. Hermes	154,779,927	5,946,377
James V. Kelley	158,343,150	2,383,154
R. Madison Murphy	149,821,407	10,904,898
William C. Nolan Jr.	158,233,955	2,492,349
Ivar B. Ramberg	159,172,090	1,554,214
Neal E. Schmale	158,009,542	2,716,762
David J. H. Smith	158,391,283	2,335,022
Caroline G. Theus	158,466,270	2,260,034

Two new incentive plans and an amendment to the existing Employee Stock Purchase Plan were all approved with a tabulation of votes to the nearest share as shown below.


	For	Against
2007 Long-Term Incentive Plan	121,195,691	26,424,490
2007 Annual Incentive Plan	144,862,536	2,752,258
Employee Stock Purchase Plan Amendments	143,959,175	3,676,738

The earlier appointment by the Audit Committee of the Board of Directors of KPMG LLP as independent registered public accounting firm for 2007 was approved with 158,445,502 shares voted in favor and 1,319,707 shares voted in opposition.

PART II – OTHER INFORMATION (Contd.)

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 31 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

(b)	A report on Form 8-K was filed on April 12, 2007 that included a News Release regarding the Company’s expected results of operations for the three-month period ended March 31, 2007.

(c)

A report on Form 8-K was filed April 24, 2007 to disclose that effective on that date the 2007 Long Term Incentive Plan of Murphy Oil Corporation was amended to (i) reduce the maximum number of shares available for grant under the plan to 6,700,000 and (ii) reduce the maximum term of options granted under this plan to seven (7) years.

(d)	A report on Form 8-K was filed on April 25, 2007 that included a News Release announcing the Company’s earnings and certain other financial information for the three-month period ended March 31, 2007.

(e)	A report on Form 8-K was filed on May 4, 2007 that included a News Release announcing an agreement with Wal-Mart Stores, Inc. to purchase parcels of property which the Company leased from Wal-Mart.

(f)

A report on Form 8-K was filed on June 13, 2007 that (i) included a News Release announcing that its Canadian subsidiary had acquired a 97% working interest in certain assets in the Tupper area in British Columbia, Canada, for a purchase price of Cdn $155 million; and (ii) the Company had amended its unsecured Revolving Credit facility with a major banking consortium under which the Company and certain of its wholly owned subsidiaries may borrow up to $1,962,500,000 until June 2010, up to $1,905,000,000 from June 2010 until June 2011, and up to $1,827,500,000 from June 2011 until June 2012.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	*MURPHY OIL CORPORATION*
		(Registrant)

	By	/s/ JOHN W. ECKART
		John W. Eckart, Vice President and Controller (Chief Accounting Officer and Duly Authorized Officer)

August 6, 2007
(Date)

EXHIBIT INDEX


Exhibit No.
12.1*		Computation of Ratio of Earnings to Fixed Charges

31.1*		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*	This exhibit is incorporated by reference within this Form 10-Q.

Exhibits other than those listed above have been omitted since they are either not required or not applicable.

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